Method for removing filter cake from a horizontal wellbore using acid foam

ABSTRACT

A composition and method for removing a filter cake from a horizontal wellbore in a subterranean formation using a composition containing a inorganic or organic acidic material, a cationic fluorocarbon surfactant, an alkyl alcohol, water optionally containing ammonium chloride and at least one of an alkyl polyglycoside and a betaine surfactant to produce a stable foam used to remove filter cake from a horizontal wellbore.

FIELD OF THE INVENTION

This invention relates to a composition and a method for removing afilter cake from a horizontal wellbore in a subterranean formation usinga composition comprising acidic material, a cationic fluorocarbonsurfactant, an alkyl alcohol, and at least one of a betaine surfactantand an alkyl polyglycoside, which produces a stable acid foam effectiveto remove a filter cake from a horizontal wellbore.

BACKGROUND OF THE INVENTION

The use of alkyl polyglycoside formulations for various cleaningoperations in wellbores is well known to those skilled in the art and isdisclosed in U.S. Pat. No. 5,977,032 issued Nov. 2, 1999 to Albert F.Chan, U.S. Pat. No. 5,830,831 issued Nov. 3, 1998 to Albert F. Chan andKieu, T. Ly, U.S. Pat. No. 5,874,386 issued Feb. 23, 1999 to Albert F.Chan, William Mark Bohon, David J. Blumer, and Kieu T. Ly, U.S. Pat. No.6,000,412 issued Dec. 14, 1999 to Albert F. Chan, William Mark Bohon,David J. Blumer, Kieu T. Ly, and William G. McLelland, U.S. Pat. No.6,112,814 issued Sep. 5, 2000 to Albert F. Chan, William Mark Bohon,David J. Blumer and Kieu T. Ly, and U.S. Pat. No. 6,090,754 issued Jul.18, 2000 to Albert F. Chan and Kieu T. Ly. These patents are herebyincorporated in their entirety by reference. Other patents that disclosethe use of alkyl polyglycosides are U.S. Pat. No. 4,985,154 issued Jan.15, 1991 to Dieter Balzer and Harald Lueders and U.S. Pat. No. 5,725,470issued Mar. 10, 1998 to Virginia L. Lazarowitz, Allen D. Urfer andGeorge A. Smith. These patents are hereby incorporated in their entiretyby reference.

The use of an aqueous liquid alkyl polyglycoside formulation forcleaning wellbores and the like has been well known and is disclosed forvarious applications in the patents referred to above. While suchformulations have been effective for removal of contaminants from anannulus between a casing and a wellbore and the like, they have not beenused to clean filter cakes, such as drill-in-fluid filter cakes, fromhorizontal wellbores.

Water-based drill-in-fluids, herein drill-in-fluids, are frequently usedin the completion of horizontal wells to produce more easily removablefilter cakes on the inside of a wellbore penetrating productive areas ofa formation. Typically the primary drilling mud includes materials wellknown to the art, such..as bentonite clays, barite, polymers, such asxanthan gum, starch and the like. These primary drilling fluids producefilter cakes which function to reduce fluid loss from the wellboreduring drilling. Drill-in-fluids are substituted for primary drillingfluids for drilling through the productive formation(s) in open-holehorizontal wells. Drill-in-fluids typically contain polymers, such asxanthan gum, starch, sized salt bridging particles, such as sizedcalcium carbonate or sodium chloride particles. Other materials may beincluded, but the primary ingredients are as listed above. Differentsized inorganic salt particles may be used.

During typical drilling operations for horizontal open-hole wellcompletions, primary drilling muds are used to drill to a depth near thetop of a producing formation(s). At this point, the primary drilling mudis switched to a drill-in-fluid that displaces the primary drillingfluid from the wellbore and is thereafter used as a drilling fluid fordrilling the wellbore through the producing formation(s). Both theprimary drilling mud and the drill-in-fluid create filter cakes on theinside of the wellbore as filtrate from the drilling mud or thedrill-in-fluid escape into the formation through the inside diameter ofthe wellbore. These filter cakes serve to stop the loss of fluids duringdrilling. Unfortunately the filter cake, once formed, also restrictsfluid flow from the formation during production.

The drill-in-fluid produces a filter cake on the inside of thefluid-producing zone, which is designed for easier removal by breakertreatments using acid, oxidizer or enzyme materials. An acid breakertreatment can constitute simply positioning an aqueous inorganic acid,such as hydrochloric acid, or an aqueous organic acid, such as formicacid, in the production zone and maintaining it in place in theproduction zone for a period of time in order to react withdrill-in-fluid filter cake components, although this is rarely achievedin a horizontal well. These filter cake masses, as mentioned previously,include materials such as starch and calcium carbonate particles, whichare readily dissolved by aqueous acids. The residual filter cake is thensloughed off the inside of the wellbore or removed from the inside ofthe wellbore by production.

As the horizontal section of a horizontal well is drilled withdrill-in-fluid, a much more extended wellbore portion is drilled in theproducing zone. For instance, the horizontal portion of the well may beup to a few thousand feet or longer. As a result, the recirculateddrill-in-fluid becomes contaminated with drilled cuttings from theformation. As the drill-in-fluid becomes more contaminated, the filtercake formed becomes more difficult to remove by a breaker treatment,even with a strong acid treatment. This difficulty is a result of thepresence of additional acid insoluble formation cuttings or fines fromthe formation in the drill-in-fluid in addition to the calcium carbonatesized salt, starch and other components of the drill-in-fluid. Thepresence of the drilled solids also affects the dissolution or removalrate of the filter cake masses, as some can be removed much slower thanothers due to blockage of access by the drilled solids on the filtercake surfaces. The result of non-uniform dissolution of some filter cakemasses will prematurely open the communications with the formation andsubsequently induces a total loss of acid treatment fluid. This is mostundesirable because the loss of acid treatment fluid will leave asignificant portion of the filter cake mass intact on the formationsurface which will continue to inhibit the flow of fluid duringproduction.

As the lateral section of the well is drilled, the contamination of thedrill-in-fluid by the formation solids increases. Solids controlequipment on the surface can help remove some of the drilled solids andmitigate the problem, but it is not a practical solution since smallerdrill solids and fines can be very difficult to remove using such solidscontrol equipment. Accordingly, the filter cake formed on the insidenear inlet (heel) surfaces of the horizontal wellbore is substantiallyclean filter cake of drill-in-fluid constituents. However the filtercake may contain substantial quantities of formation solids toward theend (toe) of the horizontal wellbore. As a result, when acid treatmentis used by simply placing an aqueous acid in the horizontal portion ofthe wellbore, the relatively clean drill-in-fluid filter cake at theheel of the horizontal wellbore can be broken up quickly.

Those filter cakes containing quantities of formation fines inincreasing percentages along the length of the horizontal wellboretoward its toe result in increasingly slower removal of the filter cakealong the length of the horizontal wellbore. As a result, the aqueousacid solution is lost into the formation through the heel of thehorizontal wellbore as the filter cake is destroyed and removed fasterthan the filter cake near the toe. The result is that the filter cake iseffectively removed, at least in part, near the heel of the horizontalwellbore but little effect is seen in the extended portions of thehorizontal wellbore beyond the near heel portion. The unremoved orunbroken filter cake will inhibit the flow of fluids during productionAttempts to remove such filter cakes more uniformly along the length ofthe horizontal portion of horizontal wellbores have been made usingslower-acting breakers, such as enzymes, oxidizing agents and the like,which are considered to break down the starch. While such techniqueshave been somewhat successful, they are very slow and typically requirefrom 36 to 48 hours or longer to be effective and also may requiredifficult, special handling at the surface. Accordingly, an improvedmethod for treating horizontal wellbores to remove filter cakes has beensought.

SUMMARY OF THE INVENTION

According to the present invention, such drill-in-fluid filter cakes areremoved by: forming an aqueous acidic foam which is stable at 200° F.for at least about 3 to about 4 hours which comprises an aqueous acidicmaterial selected from the group consisting of from about 1 to about 20weight percent of an inorganic acid and from about 1 to about 30 weightpercent of an organic acid and mixtures thereof; about 0.05 to about 3weight percent of a cationic fluorocarbon surfactant; from about 0.1 toabout 4 weight percent of an alkyl alcohol containing from about 4 toabout 8 carbon atoms; at least one of about 0.1 to about 4 weightpercent of a betaine surfactant and about 0.25 to about 10 weightpercent of an alkyl polyglycoside containing alkyl groups containingfrom about 8 to about 16 carbon atoms and mixtures thereof; and, wateroptionally containing ammonium chloride; positioning the aqueous acidicfoam in the horizontal wellbore; and, retaining the aqueous acidic foamin the horizontal wellbore for a time from about 2 to about 4 hours.

The invention further comprises a composition for producing a stableacidic foam for use in removing filter cake from a horizontal wellborein a subterranean formation, the foam. being stable at 200° F. for atleast about 3 to about 4 hours, the composition comprising: an acidicmaterial selected from the group consisting of from about 1 to about 20weight percent of an inorganic acid and from about 1 to about 30 weightpercent of an organic acid and mixtures thereof; about 0.05 to about 3weight percent of a cationic fluorocarbon surfactant; from about 0.1 toabout 4 weight percent of an alkyl alcohol containing from about 4 toabout 8 carbon atoms; and, about 0.25 to about 10 weight percent of analkyl polyglycoside containing alkyl groups containing from about 8 toabout 16 carbon atoms and mixtures thereof; and, water optionallycontaining ammonium chloride.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a horizontal wellbore suitable fortreatment by the method and composition of the present invention;

FIG. 2 shows foam stability test results in the presence of 30 weightpercent crude oil with 10 weight percent hydrochloric acid in 2 weightpercent ammonium chloride brine using 0.25 weight percent n-hexanol and0.25 weight percent FORAMOUSSE S1 with FLUORAD FC-754 concentrationsranging from 0.05-0.125 weight percent at a temperature of 95° C. (203°F.);

FIG. 3 shows foam stability test results in the presence of 30 weightpercent crude oil with 10 weight percent hydrochloric acid in 2 weightpercent ammonium chloride brine using 0.25 weight percent n-hexanol and0.50 weight percent FORAMOUSSE S1 with FLUORAD FC-754 concentrationsranging from 0.10-0.25 weight percent at a temperature of 95° C. (203°F.);

FIG. 4 shows foam stability test results in the presence of 30 weightpercent crude oil with 10 weight percent hydrochloric acid in 2 weightpercent ammonium chloride brine using 0.25 weight percent n-hexanol and1.0 weight percent FORAMOUSSE S1 with FLUORAD FC-754 concentrationsranging from 0.20-0.50 weight percent at a temperature of 95° C. (203°F.);

FIG. 5 shows foam stability from tests conducted under substantially thesame conditions as those previously shown with 0.25-1.0 weight percentFORAMOUSSE S1, but without FLUORAD FC-754 surfactant component; and,

FIG. 6 shows foam stability test results comparing four differentformulations in 0 or 15 weight percent hydrochloric acid solution at150° F. (65.5° C.) in the presence of 30 weight percent crude oil.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the description of the Figures, various pumps, valves and the like,as known to the art, which are necessary to achieve the flows describedhave not been shown in the interest of conciseness. All concentrationsare by weight percent of active ingredient in the aqueous solution orthe aqueous foam unless otherwise stated.

The surfactant foam composition of the present invention consistsessentially of an aqueous foam containing an aqueous acidic materialselected from the group consisting of from about 1 to about 20, andpreferably from about 3 to about 10, weight percent of an inorganic acidsuch as hydrochloric acid; from about 1 to about 30, and preferably fromabout 5 to about 20, weight percent, of an organic acid selected from agroup consisting of formic, acetic, propionic and citric acids; fromabout 0.05 to about 3, preferably about 0.1 to about 0.5, weight percentof a cationic fluorocarbon surfactant; from about 0.1 to about 4 weightpercent and preferably from about 0.1 to about 2 weight percent of analkyl alcohol containing from about 4 to about 8 carbon atoms; at leastone of from about 0.1 to about 4, and preferably from about 0.5 to about2.0 weight percent of a betaine surfactant; and about 0.25 to about 10,and preferably from about 0.5 to about 2 weight percent of at least onealkyl polyglycoside surfactant selected from alkyl polyglycosidescontaining alkyl groups containing from about 8 to about 16 carbon atomsand mixtures thereof. Preferably, the alkyl polyglycoside, betainesurfactant and cationic fluorocarbon surfactant comprise from about 0.5to about 6 weight percent of the aqueous foam.

The acid material may be either hydrochloric acid, an organic acid, amixture of organic acids or mixtures thereof. The acid is typicallyadded as a concentrated aqueous solution. The acid material is anecessary component of the surfactant composition since it is requiredto effectively decompose the starch cementing materials and sized saltbridging particles. Especially with carbonate particulates, the acid iseffective to dissolve the particulates.

The alkyl alcohol may be a linear or a branched alkyl alcohol and isdesirably present in an amount from about 0.1 to about 2 weight percent.The alcohol promotes the formation of microemulsions once the surfactantfoam has been spent and becomes mixed with oily fluids, such as crudeoil and condensate from the formation.

The composition further desirably comprises an amphoteric surfactantthat contains a fatty acid amido alkyl chain, a positive quaternaryammonium group and a negative carboxylate group, such as a betainesurfactant. The fatty acid group desirably contains from about 14 to 24carbon atoms and preferably from about 16 to about 20 carbon atoms. Thealkyl chain contains from about 2 to about 4 carbon atoms and preferably3 carbon atoms.

Cocoamido propyl betaine is a preferred betaine surfactant containing acocoamido propyl group. The betaine surfactant is present in a quantityfrom about 0.1 to about 4, and preferably is present in an amount fromabout 0.5 to about 2 weight percent. The cocamido propyl betaine usedwas FORAMOUSSE S1. FORAMOUSSE S1 betaine surfactant is marketed bySeppic, Inc. of Fairfield, N.J.

The foam formulation also includes from about 0.05 to about 3 weightpercent of a cationic fluorocarbon surfactant.

Suitable cationic fluorocarbon surfactants are selected from the groupconsisting of fluorinated alkyl quaternary ammonium halides. Thesurfactant consists of an insoluble fluorocarbon “tail” and awater-soluble solubilizing group. The fluorocarbon tail should contain 4to 8 carbon chain which is fluorinated, and the solubilizing group ischloride or iodide. Such a material is marketed as FLUORAD FC 754(trademark of 3M Company of St. Paul, Minn.). These materials are usefulas a component in a composition to generate a foam which remains isstable at 200° F. for at least about 3 to about 4 hours in a formation.The foam is stable up to a crude oil content of at least 30 volumepercent.

Typically water containing ammonium chloride is present in an amount upto about 6 weight percent ammonia chloride or more. Preferably theammonium chloride is present in an amount from about 2 to about 6 weightpercent

Representative drill-in-fluids have been discussed and are disclosedmore fully in DRIL-N Specialized Systems For Optimum ProductionBrochure, by Baroid Drilling Fluids, Inc. Such systems are described inthis brochure and are considered to be well known to those skilled inthe art. DRIL-N is a trademark of Baroid Drilling Fluids, Inc.

These drill-in-fluids, as indicated previously, are used to drill thewellbore through producing zones of a formation. In the course ofdrilling a wellbore, the drill-in-fluid is used in the producingintervals so that drill-in-fluid filter cakes are deposited on the wallsof the wellbore as the aqueous portion of the drill-in-fluids leaks offinto the formation as a filtrate. The removal of these drill-in-fluidfilter cakes is more easily accomplished than is the removal of filtercakes of the primary drilling fluid.

The composition described above is most effectively used by displacingit into a horizontal wellbore as a foam and maintaining it in positionin the horizontal wellbore for a period of time up to about 2 to about 4hours.

The composition is readily produced by mixture of the component partswith an aqueous liquid. The foam may be formed by the use of alternatingslugs of gas, such as air, nitrogen or the like, and the composition ora foam generation nozzle or the like in the horizontal wellbore, but ispreferably formed at the surface and injected via a tubing or the like.

Oil wells are typically completed in a number of ways. In the first typeof completion, the well is drilled generally vertically to and throughan oil-producing zone, thereafter cased with pipe and then perforated inthe oil-producing zone. This results in producing a flow channel(perforation) through the casing and the cement sheath between theoutside of the casing and the wellbore so that oil can flow freely fromthe formation through the perforation holes. Unfortunately, theperforation openings are not large relative to the area of the casing orthe area of the inside of the wellbore. Nevertheless, such completionshave been practiced widely.

In another type of completion, the well may be completed by drilling to,or near the top of an oil-bearing formation, casing the well to near thetop of the oil-bearing formation and then drilling horizontally from thevertical wellbore through the oil-bearing formation. A drill-in-fluid isused to drill through the oil-bearing formation.

Drill-in-fluids have been previously described and generally comprisebridging particulates, such as calcium carbonate or sodium chloridesized salts, in combination with starch, a polymer such as xanthan andthe like. The drill-in-fluid filter cakes are more readily removed fromthe inside of the wellbore by aqueous acid than are filter cakesproduced by the primary drilling muds.

If the well is to be completed as a horizontal open-hole, it isdesirable that the filter cake be removed from the face of the formationaround the lateral portion of the wellbore prior to production. In otherwords, the filter cakes as deposited by both the typical drilling fluidand the drill-in-fluid are positioned on the face of the formation as aresult of the escape of filtrate into the formation, leaving the starchyand particulate constituents of the filter cake on the face of theformation. Drilling fluids achieve shut off of liquid flow into theformation during drilling, thereby preventing fluid loss from thewellbore during drilling. This is a desirable feature during drillingbut is highly undesirable when the same filter cake serves to preventthe flow of fluids from the oil-bearing formation into the wellbore. Theuse of drill-in-fluids is practiced by substituting the drill-in-fluidfor the primary drilling fluid when a desired depth is reached so thatthe drill-in-fluid displaces the conventional drilling fluid from thewellbore for drilling through the oil-bearing formation. The filter cakeon the face of the oil-bearing formation thus contains the more easilyremoved sized salt particulates, starch and polymers used in theformulation of drill-in-fluids.

A horizontal well completion is shown schematically in FIG. 1. Awellbore 20 in FIG. 1 extends from a surface 22 through an overburden 34and generally horizontally in an oil-bearing formation 36. Wellbore 20comprises a casing 24, which is cemented in place by cement 26 andextends to a bottom 28 of casing 24. A packer 30 is typically placednear the bottom of casing 24 for the completion of the well. Ahorizontal (lateral) portion 32 of wellbore 20 extends generallyhorizontally into oil-bearing formation 36. A production tubing 38extends downwardly through casing 24 and into oil-bearing formation 36.Production tubing 38 may be centralized or it may lie on the bottom ofat least a portion of horizontal portion 32. A horizontal section 40 ofproduction tubing 38 may comprise a slotted liner, screen-liner, or thelike for oil production after well completion. Desirably, tubing 38extends to near a toe 42 of the horizontal section. A tube, such as acoiled tubing 44, may be extended downwardly into wellbore 20 throughtubing 38 for the injection of the foam. The foam may be produced bygenerating the foam at the surface and passing it downwardly throughtube 38 into horizontal section 32 or the foam may be produced in-situby injecting slugs of air and the composition alternately through thehorizontal wellbore. A variety of well tubing configurations arepossible as known to those skilled in the art.

Aqueous acid has been found effective to break a drill-in-fluid filtercake mass. The acid can degrade the starch, which acts as a bondingmaterial, and can dissolve carbonate bridging particles. Once the filtercake is broken, communication between the wellbore and the formationbecomes open and allows fluid movement, depending on hydrostaticpressure in the cased hole. Often acid will be lost to the formationonce an opening is established after filter cake is broken anywhere inthe horizontal hole. One difficulty in filter cake removal is to achievea uniform break in the filter cake simultaneously across the horizontalhole. This is difficult because the filter cake composition may not beof a uniform composition as deposited across the length of thehorizontal portion of the well. Filter cake near the heel tends to havemuch less drilled solids contaminants due to a cleaner drill-in fluidthan filter cake toward the toe, which will have more drilled solidcontaminants as a result of the drill-in fluid picking up solids andfines when making the new hole.

A filter cake mass containing more drilled solids has been found to beharder to break, requiring a higher acid concentration and a longersoaking time with the acid. This is possibly due to the hindrance by thedrilled solids of the acid to the starch and carbonate material of thefilter cake mass and also the reduction of available starch andcarbonate materials per unit surface area of the filter cake.

As a result, historically aqueous acid treatment has not beensatisfactory in breaking the filter cake across an open hole. In mostinstance, acid is lost to the formation after a short period of soakingtime. It is believed that the acid has broken only the filter cake massnear the heel section and escapes into the formation due to thehydrostatic pressures in the cased hole. Consequently the majority ofthe filter cake, especially toward and near the toe section, is notbroken and therefore will continue to hinder the productivity of thewell. Remedial treatment to remove unbroken filter cake near the toesection of the open hole proves to be very difficult since the open holeis no longer able to hold any aqueous liquid fluid since a leak offescape point is already established near the heel section.

Other breaker treatments using enzyme or oxidizing agents have beenpracticed. However, enzyme treatment is a slow process requiringtypically 36-48 hours of soaking time and is very selective with respectto the filter cake components. For example, some enzyme is starchspecific while other enzyme is polymer specific. Neither dissolvescarbonate bridging particles and both are sensitive to oily contaminatesin the wellbore. Enzyme treatment is usually the most costly and timeconsuming treatment since neither dissolves carbonate bridging particlesand both may require a remedial acid pill to dissolve bridging particlesto completely remove the filter cake.

Oxidizing agents have also been used in breaker treatments. Such agentsfunction as breakers by attacking the polymer linkage and breaking itinto smaller pieces. The use of oxidizing breakers is limited because ofthe more stringent handling requirements on the surface. Furthermore,the use of a remedial acid pill may also be required to dissolve thebridging particles to completely remove the filter cake.

Both of the referenced techniques have been practiced with their ownselective successful results.

According to the present invention, these filter cakes are removed bythe injection of acidic foam. The foam may be created at the surface andsimply pumped into the horizontal portion of the wellbore or it may begenerated by injecting alternating slugs of gas and liquid as thematerials are injected or the like. A foam forming head may be used onthe injection pipe near toe 42 of horizontal portion 32 and the like.Means for introducing foam into formations are well known to the art. Itis also well known to those skilled in the art that foams tend toinhibit the fluid flow and end the loss of fluids into subterraneanformation even though some portion of the filter cake mass has beenprematurely broken. This allows continued dissolution of the rest of thefilter cake along the lateral portion with acidic treatment.Accordingly, even if the acid is more effective to remove filter cake ina given portion of the horizontal wellbore than in other portions of thehorizontal wellbore, the fluid loss will be arrested by the presence ofthe foam in the portions where the acid is more quickly effective.

The foam is stable at formation conditions in the presence of crude oil,i.e., up to at least 200° F. and for times of at least 3 to 4 hours. Thefoam, as positioned in section 32, will contact the filter cake mass onthe formation surfaces of the wellbore in section 32 so thatdrill-in-fluid filter cake can be removed from these surfaces. The acidfoam is effective to remove the drill-in-fluid filter cake containingcalcium carbonate particulates, starch and the like. The acid foam isalso effective to remove the filter cake by reaction with the starch.

Further, the foam not only remains in contact with most of the surfacesof section 32, but also is effective when an area of filter cake isremoved in section 32 to prevent the escape of substantial quantities offoam into the surrounding formation. This has been a recurring problemwhen substances such as acidic aqueous solutions are used for theremoval of drill-in-fluid filter cake. Not only are such acidicsolutions more difficult to handle and to maintain in contact with allsurfaces but when an area of filter cake is prematurely removed, thewhole aqueous acid treatment fluid tends to escape into the formationwithout restriction. This is not surprising considering that onefunction of the drill-in-fluid filter cake is the prevention of theescape of fluids. In other words, the drill-in-fluid filter cake servesin certain aspects as a fluid loss control material. These benefits areachieved by using the acidic foam since the foam is stable and tends toblock the formation passages temporarily in areas from which the filtercake has been removed.

Accordingly, the foam not only remains in contact with section 32 of thehorizontal wellbore for the selected time but also inhibits the escapeof liquids from the formation. Further, the acidic foam according to thepresent invention is tolerant of crude oil. The foam is stable at crudeoil concentrations up to at least about 30 weight percent crude oil inthe foam. This permits small amounts of oil to seep into section 32while the foam is in place. Crude oil has been known to provide ananti-foaming effect.

The foam is desirably produced at a foam quality from 70 to 95 percent.This percentage refers to the percent of gas in the foam volume. Thefoam is readily prepared using air, nitrogen or any other suitable gas.

The higher quality foams will be of a quality of about 80 to about 90percent. Many types of foam that have been previously proposed for suchuses are readily broken by the combination of high temperature and highacid concentrations in the presence of oil. The present foams are notsusceptible to breaking at temperatures up to at least 200° F. The foamsof the present invention readily tolerate acids up to the limitsdiscussed above and are stable in the presence of up to 30 percent oilin the foam. This permits cleaning of the horizontal portion of thewellbore while retaining foam stability. The spent foam or itsconstituents are then readily produced from the horizontal wellbore withthe produced oil.

In the following examples, it is demonstrated that the foams of thepresent invention have the required stability at elevated temperaturesand are effective to remove drill-in-fluid filter cake and are tolerantto the presence of oil. These advantages, taken with the ability of thefoam to restrict the loss of foam from the horizontal wellbore whenareas of filter cake have been removed lead to a surprisingly superiorand effective method for removing drill-in-fluid filter cake from ahorizontal wellbore.

EXAMPLES

Foam Test Procedure in Silicon Oil Bath

Equipment used in the test was: KIMBLE brand 16×150 mm borosilicateglass round bottom tubes with marking spots and corresponding phenoliccaps and 10 cc of fluid. The fluid was measured by weight as well as thecrude oil, incorporating its density. Up to 20 vials can be tested atthe same time.

The vials were filled with 10 cc of fluid, capped and labeled. They wereplaced into a preheated oil both at 95° C. and left for 20 minutes toheat up. Each vial was taken out of the bath and opened to releasepressure buildup and then the caps were re-tightened. The solution wasthen mixed gently by turning the vials upside down three times (toequilibrate the solution). The vials were returned to the preheated oilfor 5 minutes in order to return to the 95° C. temperature. The vialswere then again individually vented and recapped. The vials were thenplaced in a mechanical shaking device and rigorously shaken for 12-13times before being placed back in the oil bath, at which time a stopwatch was started. The foam height was then observed starting at 0minutes time and at various intervals, depending on foam ability.

Results

The test results show the effects of surfactant composition for FLUORADFC-754 and FORAMOUSSE S1 or APG 300 in combination on foam stability.The tests in FIGS. 2-5 were run at 95° C. (203° F.) temperature with 10weight percent hydrochloric acid containing 2 weight percent ammoniumchloride in the presence of 30 weight percent crude oil. The tests inFIG. 6 were run at 150° F. (65.5° C.) temperature with 15 weight percenthydrochloric acid containing 2 weight percent ammonium chloride in thepresence of 30 weight percent crude oil. FC-754 is FLUORAD FC-754, FS-1is FORAMOUSSE S1, APG 300 is a C₉-C₁₁ alkyl polyglycoside with a degreeof polymerization number of 1.4, WC-66 is crude oil from the WestCameron 66 field, EI-175 is crude oil from the Eugene Island 175 fieldand C6OH is n-hexanol. The other abbreviations are standardabbreviations.

The tests in FIG. 2 were performed at the conditions shown with foamsproduced using surfactant compositions which contain 0.25 weight percentFS-1 and FC-754 concentrations ranging from 0.05 to 0.125 weight percentwith a corresponding surfactant ratio between FS-1 and FC-754 rangingfrom 5.0 to 2.0. These had the foam stabilities shown.

FIG. 3 shows the test results for 0.50 weight percent FS-1 and a higherFC-754 concentrations ranging from 0.10 to 0.25 weight percent in orderto keep a similar corresponding ratio between FS-1 and FC-754 from 5.0to 2.0.

FIG. 4 shows results for tests conducted under substantially the sameconditions as those previously shown but with higher concentrations of1.0 weight percent FS-1 and 0.20 to 0.50 weight percent of FC-754, whilekeeping a similar corresponding ratio between FS-1 and FC-754 from 5.0to 2.0. The crude oil was Eugene Island 175 field crude oil.

FIG. 5 shows foam stability test results under substantially the sameconditions as those previously show, using FORAMOUSSE S1 concentrationranging from 0.25 to 1.0 weight percent, but without the addition ofFLUORAD FC-754 surfactant.

The first two graphs in FIG. 6 provide a comparison of foam stabilitytest results for a 2 weight percent FORAMOUSSE S1 in 0 and 15 weightpercent hydrochloric acid. Experimental conditions are as shown and wereused with each of the four graphs shown.

In a third graph the FORAMOUSSE S1 was used with FLUORAD FC-754 and 15weight percent hydrochloric acid at the concentrations shown.

In the fourth graph, alkyl polyglycoside (APG 300) was used incombination with the FLUORAD FC-754 and 15 weight percent hydrochloricacid at the concentrations shown. Clearly the combination of theFORAMOUSSE S1 with the FLUORAD FC-754 has resulted in superior foam,which remained stable for up to 300 minutes. Similarly, the combinationof APG 300 with FLUORAD FC-754 has resulted in a foam which has similarstability. Much less stability is obtained using the FORAMOUSSE S1 alonein the presence of 15 weight percent hydrochloric acid.

The test results clearly show that surprisingly stable foams areproduced by the use of either the FORAMOUSSE S1 or the alkylpolyglycoside in combination with FLUORAD FC-754.

This surprising superiority permits the use of acid foam, which is shownto be stable in the presence of crude oil, for filter cake removal in ahorizontal wellbore.

While the present invention has been described by reference to certainof its preferred embodiments, it is pointed out that the embodimentsdescribed are illustrative rather than limiting in nature and that manyvariations and modifications are possible within the scope of thepresent invention. Many such variations and modifications may beconsidered obvious and desirable by those skilled in the art based upona review of the foregoing description of preferred embodiments.

1. A method for removing a filter cake from a horizontal wellbore in asubterranean formation, the method comprising: a) forming a stableaqueous acidic foam, the foam being stable at 200° F. for at least about3 to about 4 hours and comprising: i) an aqueous acidic materialselected from the group consisting of from about 1 to about 20 weightpercent of an inorganic acid, from about 1 to about 30 weight percent ofan organic acid and mixtures thereof; ii) about 0.05 to about 3 weightpercent of a cationic fluorocarbon surfactant; iii) about 0.1 to about 4weight percent of an alkyl alcohol containing from about 4 to about 8carbon atoms; iii) at least one of about 0.1 to about 4 weight percentof a betaine surfactant and about 0.25 to about 10 weight percent of analkyl polyglycoside containing alkyl groups containing from about 8 toabout 16 carbon atoms and mixtures thereof; and; iv) water optionallycontaining ammonium chloride; b) positioning the aqueous acidic foam inthe horizontal wellbore; and, c) retaining the aqueous acidic foam inthe horizontal wellbore for a time from about 2 to about 4 hours.
 2. Themethod of claim 1 wherein the stable aqueous acidic foam contains about0.1 to about 2 weight percent of an alkyl alcohol containing from about4 to about 8 carbon atoms.
 3. The method of claim 1 wherein the filtercake is a filter cake from a water-based drill-in-fluid.
 4. The methodof claim 1 wherein the drill-in-fluid filter cake comprises a starch, apolymer and sized inorganic salt particles.
 5. The method of claim 1wherein the sized inorganic salt is calcium carbonate or sodiumchloride.
 6. The method of claim 1 wherein the alkyl polyglycoside ispresent in an amount from about 0.5 to about 2 weight percent.
 7. Themethod of claim 1 wherein the acidic material is an inorganic acid andwherein the inorganic acid is present in an amount from about 3 to about10 weight percent.
 8. The method of claim 8 wherein the inorganic acidis hydrochloric acid.
 9. The method of claim 1 wherein the organic acidis selected from the group consisting of formic, acetic, propronic andcitric acids and combinations thereof.
 10. The method of claim 9 whereinthe organic acid is present in an amount from about 5 to about 20 weightpercent.
 11. The method of claim 1 wherein the foam is stable in thepresence of up to about 30 weight percent crude oil in the foam.
 12. Themethod of claim 1 wherein the betaine surfactant is selected from thegroup consisting of fatty acid amido propyl betaines.
 13. The method ofclaim 12 wherein the fatty acid groups contain from about 16 to about 20carbon atoms.
 14. The method of claim 1 wherein the cationicfluorocarbon co-surfactant fluorocarbon is selected from the groupconsisting of fluorinated alkyl quaternary ammonium chlorides. Themethod of claim 14 wherein the fluorinated alkyl group contains from 4to 8 carbon atoms.
 15. A composition for producing a stable acidic foamfor use in removing filter cake from a horizontal wellbore in asubterranean formation, the foam being stable at 200° F. for at leastabout 3 to about 4 hours, the composition comprising: a) an acidicmaterial selected from the group consisting of from about 1 to about 20weight percent of an inorganic acid, from about 1 to about 30 weightpercent of an organic acid and mixtures thereof; b) about 0.05 to about3 weight percent of a cationic fluorocarbon co-surfactant; c) about 0.1to about 4 weight percent of an alkyl alcohol containing from about 4 toabout 8 carbon atoms; d) at least one of about 0.1 to about 4 weightpercent of a betaine surfactant and about 0.25 to about 10 weightpercent of an alkyl polyglycoside containing alkyl groups containingfrom about 8 to about 16 carbon atoms and mixtures thereof and; e) wateroptionally containing ammonium chloride.
 16. The method of claim 15wherein the alkyl polyglycoside is present in an amount from about 0.5to about 2 weight percent.
 17. The method of claim 15 wherein thecomposition includes the alkyl alcohol in an amount from about 0.1 toabout 2 weight percent.
 18. The method of claim 15 wherein the acidicmaterial is an inorganic acid and wherein the inorganic acid is presentin an amount from about 3 to about 10 weight percent.
 19. The method ofclaim 15 wherein the acidic material is an organic acid and is presentin an amount from about 5 to about 20 weight percent.
 20. The method ofclaim 15 wherein the foam is stable in the presence of up to about 30weight percent oil in the foam.
 21. The method of claim 15 wherein thebetaine surfactant is selected from the group consisting of fatty acidamido propyl betaines.
 22. The method of claim 15 wherein the organicacid is selected from the group consisting of formic, acetic, propronicand citric acids and combinations thereof.
 23. The method of claim 15wherein the cationic surfactant fluorocarbon is selected from the groupconsisting of fluorinated alkyl quaternary ammonium chlorides.
 24. Themethod of claim 15 wherein the alkyl alcohol is present in an amountfrom about 0.1 to about 2 weight percent.